A drilling fluid or mud is a specially designed fluid that is circulated through a wellbore as the wellbore is being drilled to facilitate the drilling operation. The various functions of a drilling fluid include removing drill cuttings from the wellbore, cooling and lubricating the drill bit, aiding in support of the drill pipe and drill bit, and providing a hydrostatic head to maintain the integrity of the wellbore walls and prevent well blowouts. Specific drilling fluid systems are selected to optimize a drilling operation in accordance with the characteristics of a particular geological formation.
Oil or synthetic fluid-based muds are normally used to drill swelling or sloughing shales, salt, gypsum, anhydrite or other evaporate formations, hydrogen sulfide-containing formations, and hot (greater than about 300° F.) holes, but may be used in other holes penetrating a subterranean formation as well. Unless indicated otherwise, the terms “oil mud” or “oil-based mud or drilling fluid” shall be understood to include synthetic oils or other synthetic fluids as well as natural or traditional oils, and such oils shall be understood to comprise invert emulsions.
Oil-based muds used in drilling typically comprise: a base oil (or synthetic fluid) comprising the external phase of an invert emulsion; a saline, aqueous solution (typically a solution comprising about 30% calcium chloride) comprising the internal phase of the invert emulsion; emulsifiers at the interface of the internal and external phases; and other agents or additives for suspension, weight or density, oil-wetting, fluid loss or filtration control, and rheology control. Such additives commonly include organophilic clays and organophilic lignites. An oil-based or invert emulsion-based drilling fluid may commonly comprise between about 50:50 to about 95:5 by volume oil or oleaginous phase to water or aqueous phase.
“Clay-free” invert emulsion-based drilling fluids offer different properties over drilling fluids containing organophilic clays. As used herein, the term “clay-free” (or “clayless”) means a drilling fluid made without addition of any organophilic clays or lignites to the drilling fluid composition.
In conventional invert emulsion drilling fluids, and in some “clay-free” invert-emulsion drilling fluids, brine rather than pure water is used for the internal phase because the salts such as calcium chloride in the brine enable balancing of osmotic pressures during drilling through shales. That is, the salt helps keep the water activity of the drilling fluid the same as the water activity of the shale, thereby preventing the flow of water from the drilling fluid into the shales and thus avoiding swelling of the shales. The concentration of salt used in the internal phase depends on the activity of water present in the shales.
Use of high concentrations of chloride salts can give rise to disposal issues and environmental concerns and can also result in high conductivity which interferes with the sensitivity of induction logs during exploratory drilling. Alternative electrolytes, such as potassium acetate or formate, have been used, but these salts are often cost prohibitive and still limit induction log sensitivity. Other substitutes such as potassium chloride, sodium chloride and magnesium sulfate result in similar disposal issues.
Alcohols, particularly glycerols, polyglycerols, and cyclicetherpolyols have also been tried as an alternative to calcium chloride brines for the internal phase of conventional invert emulsion drilling fluids. An advantage of using alcohols in the internal phase is that much of the concern for the ionic character of the internal phase is no longer required. When water is not present in the system, hydration of the shales is greatly reduced. Alcohols can still interact with the clays of the shales but swelling is considered still significantly less than with water. Conventionally, the problem with using alcohols as an internal phase of an invert emulsion is that the invert emulsions tend to be less stable at the high temperatures commonly encountered in subterranean formations during drilling for hydrocarbons. This instability is believed to be due to the alcohols tending to separate or become insoluble at elevated temperatures. Even when more heat tolerant alcohols are employed, barite settling and an undesirably high filtrate rate indicating invert emulsion instability at high temperatures and high pressures have been observed.
Clay-free invert emulsion fluids formulated without the organophilic clay provide gels which are high but yet break easily on application of lower pump pressures than usual. Clay-free invert emulsion drilling fluids, like INNOVERT™ drilling fluid available from Halliburton Energy Services, Inc., in Houston, Tex., for example, have been shown to yield high performance drilling, with “fragile gel” strengths and rheology leading to lower equivalent circulating density (ECDs) and improved rate of penetration (ROP). ECD is the effective density exerted by a circulating fluid against the formation, and accounts for the pressure drop in the annulus above the point being considered. Due to easy conversion from a gel to liquid phase, the equivalent circulating density spikes usually observed are lower or absent when breaking circulation, tripping in & out and during connections. The lower or absent ECD spikes reduces the probability of induced fractures which translates into lower fluid losses into the formation, where fluid is lost (e.g., leaking off) into other portions or fractures in the formation besides the dominant fracture. High gel strength observed in clay free invert emulsion fluids provides enough suspension to prevent any barite from settling reducing incidents of a density gradient and worst case scenario which is SAG, the settling of particles in the annulus of a well, that can lead to a well control situation. The high gels and also aids in hole cleaning by suspending the drill solids and preventing them from falling back to the bottom and interfering with the function of the bit. One more advantage realized without the addition of the organophilic clay is the absence of thick progressive gels that are observed after long static periods. A thick gel can require enormous pump pressures before the gel transition to a liquid and flow. A high pump pressure implies a high ECD which is experienced at the bottom leading to induced fractures and therefore losses.
An essential criterion for assessing the utility of a fluid as a drilling fluid or as a well service fluid may include the fluid's rheological parameters, particularly under simulated drilling and well bore conditions. For use as a drilling fluid, or as a fluid for servicing a well, a fluid generally should be capable of maintaining certain viscosities suitable for drilling and circulation in the well bore. Preferably, a drilling fluid will be sufficiently viscous to be capable of supporting and carrying the well drill cuttings to the surface without being so viscous as to interfere with the drilling operation. Moreover, a drilling fluid must be sufficiently viscous to be able to suspend barite and other weighting agents. However, increased viscosity can result in problematic sticking of the drill string, and increased circulating pressures can contribute to lost circulation problems.
It was observed that clay free invert emulsion fluids formulated at low to medium density (8.5-12 ppg) without the addition can experience lower than the desired rheology which is required for the drilling fluid to perform its hole functions. Thus, a need exists for a clay-free invert emulsion fluid with improved rheological and stability characteristics.